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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________________

FORM 10-K

(Mark One)

    ☒

    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2024

    ☐

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to

Commission File Number: 001-32886

_______________________________

CONTINENTAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

_______________________________

Registrant’s telephone number, including area code: (405) 234-9000

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

_______________________________

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No ¨

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ¨

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of this filing.

DOCUMENTS INCORPORATED BY REFERENCE

None.

Table of Contents


PART I
Item 1.	Business	1
	General	1
	Our Business Strategies	1
	Crude Oil and Natural Gas Operations	1
	Proved Reserves	1
	Developed and Undeveloped Acreage	4
	Drilling Activity	4
	Summary of Crude Oil and Natural Gas Properties and Projects	5
	Production and Price History	6
	Productive Wells	7
	Title to Properties	7
	Marketing	7
	Competition	8
	Regulation of the Crude Oil and Natural Gas Industry	8
	Human Capital	9
	Company Contact Information	10
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	21
Item 1C.	Cybersecurity	21
Item 2.	Properties	22
Item 3.	Legal Proceedings	22
Item 4.	Mine Safety Disclosures	22

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6.	Reserved	23
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	35
Item 8.	Financial Statements and Supplementary Data	37
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	69
Item 9A.	Controls and Procedures	69
Item 9B.	Other Information	71
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	71

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	72
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	77
Item 13.	Certain Relationships and Related Transactions, and Director Independence	77
Item 14.	Principal Accountant Fees and Services	78

PART IV
Item 15.	Exhibits and Financial Statement Schedules	79

Table of Contents

Glossary of Crude Oil and Natural Gas Terms

The terms defined in this section may be used throughout this report:

“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcf” One billion cubic feet of natural gas.

“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.

“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.

“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.

“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.

“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“gross acres” or “gross wells” Refers to the total acres or wells in which a working interest is owned.

“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.

“MBoe” One thousand Boe.

“Mcf” One thousand cubic feet of natural gas.

“MMBo” One million barrels of crude oil.

“MMBoe” One million Boe.

“MMBtu” One million British thermal units.

“MMcf” One million cubic feet of natural gas.

“net acres” or “net wells” Refers to the sum of the fractional working interests owned in gross acres or gross wells.

“NGL” or "NGLs" Refers to natural gas liquids, which are hydrocarbon products that are separated during natural gas processing and include ethane, propane, isobutane, normal butane, and natural gasoline.

“NYMEX” The New York Mercantile Exchange.

“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.

“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.

Table of Contents

“residue gas” Refers to gas that has been processed to remove natural gas liquids.

“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.

“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate.

“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Table of Contents

Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995

This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include, but are not limited to, statements about:

•

our strategy;

•

our business and financial plans;

•

our future operations;

•

our proved reserves and related development plans;

•

technology;

•

future crude oil, natural gas liquids, and natural gas prices and differentials;

•

the timing and amount of future production of crude oil, natural gas liquids, and natural gas and flaring activities;

•

the amount, nature and timing of capital expenditures;

•

estimated revenues, expenses and results of operations;

•

drilling and completing of wells;

•

shutting in of production and the resumption of production activities;

•

competition;

•

marketing of crude oil, natural gas, and natural gas liquids;

•

transportation of crude oil, natural gas, and natural gas liquids to markets;

•

property exploitation, property acquisitions and dispositions, strategic investments, or joint development opportunities;

•

costs of exploiting and developing our properties and conducting other operations, including any impacts from inflation;

•

our financial position;

•

the timing and amount of debt borrowings or repayments;

•

the timing and amount of income tax payments and payments the Company may be obligated to make pursuant to the stock redemption agreement described in Note 7. Fair Value Measurements—Stock Redemption Option;

•

current and potential litigation matters;

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geopolitical events and conditions in, or affecting other, crude oil-producing or natural gas-producing nations;

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credit markets;

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our liquidity and access to capital;

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the impact of governmental policies, laws, regulations, tariffs, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;

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our future operating and financial results;

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our future commodity or other hedging arrangements; and

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the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.

Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given

iii

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that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report and other disclosures or announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Additionally, new factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.

Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.

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Part I

You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.

Item 1. Business

Nature of business

We are an independent crude oil and natural gas company formed in 1967 engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas.

We focus our activities in large crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions and apply our geologic and operational expertise to drill and develop properties at attractive rates of return. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies, pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations.

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding. We continue to furnish Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K with the SEC as required by our senior note indentures. See Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction for additional information.

Our Business Strategies

Our business strategies continue to be focused on increasing enterprise value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. For 2025, our primary business strategies will include:

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Continuing to exercise capital discipline and operational excellence to maximize cash flow generation;

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Reducing outstanding debt and strengthening our balance sheet to further enhance financial flexibility;

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Continuing to optimize the efficiency of our capital programs and production operations to further reduce costs and enhance returns; and

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Driving continued improvement in our health, safety, and environmental performance and governance programs.

Crude Oil and Natural Gas Operations

Proved Reserves

Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.

The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2024. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. Our reserve estimates as of December 31, 2024 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 97% of our total proved reserves as of December 31, 2024. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.

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Our estimated proved reserves and related future net revenues at December 31, 2024 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2024 through December 2024, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $75.48 per Bbl for crude oil and $2.13 per MMBtu for natural gas ($71.59 per Bbl for crude oil and $1.55 per Mcf for natural gas adjusted for location and quality differentials).

The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2024.


	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Proved developed producing		405,269		3,288,444		953,343
Proved developed non-producing		3,125		19,901		6,442
Proved undeveloped		430,512		2,607,079		865,025
Total proved reserves		838,906		5,915,424		1,824,810

The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2024.


	Proved Developed						Proved Undeveloped
	Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		Crude Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)
Bakken		172,985		998,121		339,339		133,569		507,806		218,203
Anadarko Basin		76,801		1,871,025		388,638		91,933		1,510,066		343,611
Powder River Basin		38,208		133,604		60,475		62,982		118,219		82,685
Permian Basin		93,688		298,052		143,364		142,028		470,988		220,526
All other		26,712		7,543		27,969		—		—		—
Total		408,394		3,308,345		959,785		430,512		2,607,079		865,025

The following table provides information regarding changes in total estimated proved reserves for the periods presented.


	Year Ended December 31,
MBoe	2024			2023			2022
Proved reserves at beginning of year		1,847,089			1,863,764			1,645,310
Revisions of previous estimates		(276,784	)		(369,264	)		(133,061	)
Extensions, discoveries and other additions		452,530			438,367			395,490
Production		(155,914	)		(160,660	)		(146,657	)
Sales of minerals in place		(42,223	)		(15,594	)		(144	)
Purchases of minerals in place		112			90,476			102,826
Proved reserves at end of year		1,824,810			1,847,089			1,863,764

Revisions of previous estimates. Revisions for 2024 are comprised of (i) downward price revisions of 6 MMBo and 138 Bcf (totaling 29 MMBoe) due to a decrease in average crude oil and natural gas prices in 2024 compared to 2023, (ii) the removal of 86 MMBo and 382 Bcf (totaling 149 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return, (iii) downward revisions of 79 MMBo and 569 Bcf (totaling 174 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities, economics, performance, and other factors, and (iv) downward revisions of 13 MMBo and upward revisions of 528 Bcf (totaling a net upward revision of 75 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors.

Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs. For 2024, proved reserve additions totaled 453 MMBoe. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2024 drilling activities.

Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.

Purchases of minerals in place. Purchases in 2024, 2023, and 2022 were attributable to our acquisitions of properties as discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 2. Property Acquisitions and Dispositions.

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Proved Undeveloped Reserves

All of our PUD reserves at December 31, 2024 are located in our most active development areas. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2024. Our PUD reserves at December 31, 2024 include 69 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing (“DUC wells”). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.


	Crude Oil (MBbls)			Natural Gas (MMcf)			Total (MBoe)
Proved undeveloped reserves at December 31, 2023		512,183			2,376,765			908,310
Revisions of previous estimates		(171,172	)		(859,093	)		(314,354	)
Extensions, discoveries and other additions		181,047			1,398,906			414,198
Sales of minerals in place		(1,448	)		(4,273	)		(2,160	)
Conversion to proved developed reserves		(90,098	)		(305,226	)		(140,969	)
Proved undeveloped reserves at December 31, 2024		430,512			2,607,079			865,025

Revisions of previous estimates. As previously discussed, in 2024 we removed 86 MMBo and 382 Bcf (totaling 149 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to continual refinement of our drilling and development programs and reallocation of capital to areas providing the best opportunities to improve efficiencies, recoveries, and rates of return. Additionally, changes in anticipated well densities, economics, performance, and other factors resulted in downward PUD reserve revisions of 79 MMBo and 569 Bcf (totaling 174 MMBoe) in 2024. The decreases in average crude oil and natural gas prices in 2024 resulted in downward price revisions of 1 MMBo and 14 Bcf (totaling 3 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in downward revisions of 5 MMBo and upward revisions of 106 Bcf (totaling a net upward revision of 12 MMBoe) in 2024.

Extensions, discoveries and other additions. Extensions, discoveries and other additions were due to successful drilling activities and continual refinement of our drilling and development programs.

Sales of minerals in place. We had no individually significant dispositions of PUD reserves in 2024.

Conversion to proved developed reserves. In 2024, we developed approximately 16% of our PUD locations and 16% of our PUD reserves booked as of December 31, 2023 through the drilling and completion of 334 gross (184 net) development wells at an aggregate capital cost of approximately $1.3 billion incurred in 2024.

Development plans. We have acquired substantial leasehold positions in our key operating areas. Our drilling programs to date in our historical operating areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. Our inventory of DUC wells classified as PUDs total 146 gross (76 net) operated and non-operated locations at December 31, 2024 and represent 8% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2024 and only the remaining completion costs are included in future development plans.

Estimated future development costs relating to the development of PUD reserves at December 31, 2024 are projected to be approximately $1.9 billion in 2025, $1.8 billion in 2026, $2.1 billion in 2027, $2.2 billion in 2028, and $1.8 billion in 2029. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 2024 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, 2024. We had no PUD reserves at December 31, 2024 that remain undrilled beyond five years from the date of initial booking.

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Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process

Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 97% of our total proved reserves as of December 31, 2024 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our Manager of Corporate Resource Development is the technical person primarily responsible for overseeing the preparation of our reserve estimates. The Manager of Corporate Resource Development reports to our Chief Financial Officer and Executive Vice President of Strategic Planning. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by certain members of senior management before the information is filed with the SEC on Form 10-K.

Developed and Undeveloped Acreage

The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2024:


	Developed acres				Undeveloped acres				Total
	Gross		Net		Gross		Net		Gross		Net
Bakken		1,104,072		710,177		99,035		56,591		1,203,107		766,768
Anadarko Basin		471,644		284,833		413,208		218,831		884,852		503,664
Powder River Basin		238,865		181,252		252,114		179,424		490,979		360,676
Permian Basin		127,409		112,743		153,308		102,964		280,717		215,707
All other		164,345		141,272		220,880		141,424		385,225		282,696
Total		2,106,335		1,430,277		1,138,545		699,234		3,244,880		2,129,511

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2024 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.


	2025				2026				2027
	Gross		Net		Gross		Net		Gross		Net
Bakken		5,410		3,134		12,047		7,584		2,766		1,300
Anadarko Basin		88,060		48,187		36,939		22,798		29,456		16,771
Powder River Basin		4,198		2,985		10,206		6,764		2,332		915
Permian Basin		20,221		15,163		35,714		27,401		28,595		11,456
All other		11,438		6,111		23,290		16,356		15,355		8,974
Total		129,327		75,580		118,196		80,903		78,504		39,416

Drilling Activity

During the three years ended December 31, 2024, we participated in the drilling and completion of exploratory and development wells as set forth in the table below.


	2024				2023				2022
	Gross		Net		Gross		Net		Gross		Net
Exploratory wells:
Crude oil		47		39.3		33		25.9		17		12.1
Natural gas		—		—		—		—		2		—
Dry holes		—		—		—		—		1		1
Total exploratory wells		47		39.3		33		25.9		20		13.1
Development wells:
Crude oil		417		194.5		548		259.0		407		153.6
Natural gas		2		0.1		27		7.6		65		28.8
Dry holes		—		—		—		—		—		—
Total development wells		419		194.6		575		266.6		472		182.4
Total wells		466		233.9		608		292.5		492		195.5

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As of December 31, 2024, there were 260 gross (134 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.

Summary of Crude Oil and Natural Gas Properties and Projects

Following is a discussion of 2024 activities in our key operating areas.

Bakken Field

Our total Bakken production averaged 189,787 Boe per day for the fourth quarter of 2024, down 14% from the 2023 fourth quarter. For the year ended December 31, 2024, our average daily Bakken production decreased 4% compared to 2023. In 2024, we participated in the drilling and completion of 242 gross (96 net) wells in the Bakken compared to 363 gross (166 net) wells in 2023.

Our Bakken properties represented 31% of our total proved reserves at December 31, 2024 and 45% of our average daily Boe production for the 2024 fourth quarter. Our total proved Bakken field reserves as of December 31, 2024 were 558 MMBoe, a decrease of 14% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the Bakken totaled 690 gross (368 net) wells as of December 31, 2024.

Anadarko Basin

Our properties in the Anadarko Basin represented 40% of our total proved reserves as of December 31, 2024 and 30% of our average daily Boe production for the fourth quarter of 2024. Production in the Anadarko Basin averaged 126,068 Boe per day during the fourth quarter of 2024, down 13% compared to the 2023 fourth quarter. We participated in the drilling and completion of 95 gross (45 net) wells in the Anadarko Basin during 2024 compared to 120 gross (43 net) wells in 2023.

Our proved reserves in the Anadarko Basin as of December 31, 2024 totaled 732 MMBoe, an increase of 12% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the Anadarko Basin totaled 338 gross (202 net) wells as of December 31, 2024.

Powder River Basin

Our Powder River properties represented 8% of our total proved reserves as of December 31, 2024 and 6% of our average daily Boe production for the 2024 fourth quarter. Our production in the Powder River Basin averaged 27,215 Boe per day for the fourth quarter of 2024, an increase of 6% compared to the 2023 fourth quarter. During 2024, we participated in the drilling and completion of 56 gross (25 net) wells in the play compared to 53 gross (17 net) wells in 2023.

Our proved reserves in the Powder River Basin totaled 143 MMBoe as of December 31, 2024, an increase of 3% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the play totaled 133 gross (94 net) wells as of December 31, 2024.

Permian Basin

Our Permian properties represented 20% of our total proved reserves at December 31, 2024 and 18% of our average daily Boe production for the 2024 fourth quarter. Our production in the Permian Basin averaged 74,334 Boe per day for the fourth quarter of 2024, an increase of 27% compared to the 2023 fourth quarter. During 2024, we participated in the drilling and completion of 73 gross (68 net) wells in the play compared to 72 gross (66 net) wells in 2023.

Our proved reserves in the Permian Basin totaled 364 MMBoe as of December 31, 2024, a decrease of 6% compared to December 31, 2023. Our inventory of proved undeveloped drilling locations in the play totaled 422 gross (361 net) wells at year-end 2024.

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Production and Price History

The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2024, 2023 and 2022 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2024.


	Year ended December 31,
	2024		2023		2022
Net production volumes:
Crude oil (MBbls)
North Dakota Bakken		44,197		48,032		39,917
SCOOP		12,426		11,652		10,051
Permian Delaware		17,343		14,762		11,832
Total Company		84,139		84,710		72,827
Natural gas (MMcf)
North Dakota Bakken		153,389		146,026		124,411
SCOOP		169,031		179,165		185,755
Permian Delaware		38,414		27,980		20,804
Total Company		430,649		455,698		442,980
Crude oil equivalents (MBoe)
North Dakota Bakken		69,762		72,370		60,652
SCOOP		40,598		41,513		41,010
Permian Delaware		23,745		19,425		15,300
Total Company		155,914		160,660		146,657
Average sales prices:
Crude oil ($/Bbl)
North Dakota Bakken	$	75.01	$	76.41	$	94.51
SCOOP		74.92		76.82		94.58
Permian Delaware		76.39		76.21		95.14
Total Company		75.18		76.89		94.95
Natural gas ($/Mcf)
North Dakota Bakken	$	1.80	$	2.54	$	8.30
SCOOP		2.76		2.93		7.00
Permian Delaware		1.54		2.53		7.27
Total Company		2.16		2.60		7.15
Average costs per Boe:
Production expenses ($/Boe)
North Dakota Bakken	$	5.82	$	5.23	$	5.05
SCOOP		1.79		1.50		1.44
Permian Delaware		5.41		5.72		7.27
Total Company		4.94		4.47		4.24
Production and ad valorem taxes ($/Boe)	$	3.57	$	3.76	$	4.98
General and administrative expenses ($/Boe)	$	1.69	$	1.74	$	2.74
DD&A expense ($/Boe)	$	15.93	$	14.11	$	12.86

The following table sets forth information regarding our average daily production by region for the fourth quarter of 2024:


	Fourth Quarter 2024 Daily Production
	Crude Oil (Bbls per day)		Natural Gas (Mcf per day)		Total (Boe per day)
Bakken		120,054		418,400		189,787
Anadarko Basin		37,169		533,390		126,068
Powder River Basin		17,948		55,600		27,215
Permian Basin		51,692		135,850		74,334
All other		5,050		68		5,061
Total		231,913		1,143,308		422,465

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Productive Wells

Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2024. One or more completions in the same well bore are counted as one well.


	Crude Oil Wells				Natural Gas Wells				Total Wells
	Gross		Net		Gross		Net		Gross		Net
Bakken		6,181		2,328		—		—		6,181		2,328
Anadarko Basin		997		453		731		242		1,728		695
Powder River Basin		652		454		12		10		664		464
Permian Basin		619		520		52		29		671		549
All other		264		250		20		2		284		252
Total		8,713		4,005		815		283		9,528		4,288

Title to Properties

As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.

For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.

Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title issues, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.

The Company has cured material title opinion issues as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.

Marketing

We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, Powder River, Permian, and Anadarko basins we have significant volumes of production directly connected to pipeline gathering systems, with the remaining production primarily transported by truck to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they have purchased from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.

We sell most of our operated natural gas and natural gas liquids production to midstream customers at our lease locations based on market prices in the field where the sales occur, with the remaining production sold at centrally gathered locations or natural gas processing plants. These contracts include multi-year term agreements, many with acreage dedications. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. When we do take volumes in kind, we pay third parties to transport the volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the downstream markets are mostly under daily and monthly packaged volumes deals, shorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas and NGL production from non-operated properties is generally marketed at the discretion of the operators.

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Competition

We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for crude oil and natural gas properties, minerals, and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. In addition, supply chain disruptions in recent years have led to shortages of certain materials and equipment and increased costs. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased. Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and technological advances in energy generation devices may result in reduced demand for the crude oil and natural gas we produce.

Regulation of the Crude Oil and Natural Gas Industry

All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended, repealed, or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they will affect our similarly situated competitors.

The following are significant areas of regulation that may affect us in the areas in which we operate.

Environmental, health, and safety regulation

We are subject to stringent, complex, and overlapping federal, state, and local laws, rules and regulations governing environmental compliance, and occupational safety and health, as well as the discharge of materials into, and the protection of, the environment and natural resources. Environmental, health, and safety laws, rules and regulations may relate to, among other things:

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the discharge or other release of pollutants into federal and state waters and the ambient air;

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assessing the environmental impact of seismic acquisition, drilling and construction activities;

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the generation, storage, transportation and disposal of waste materials, including hazardous substances;

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the emission of certain gases, including methane, into the atmosphere;

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the acquisition of various permits to conduct exploration, drilling and production operations;

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the restriction of types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transportation activities;

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the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;

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the requirement of remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells;

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the imposition of substantial liabilities for pollution resulting from drilling and production operations;

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the development of emergency response and spill contingency plans; and

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worker protection.

These laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of our crude oil and natural gas production to a rate that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Any regulatory changes that impose further requirements on domestic producers for emissions control, waste handling, disposal, cleanup and remediation could have a significant impact on our operating costs and production of oil and gas. Additionally, certain of these

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environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental, health, and safety laws, rules, and regulations.

Other regulation of the oil and gas industry

The Company’s oil and gas operations are subject to various federal, state, and local laws and regulations that relate to matters including, among other things:

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location, drilling and casing of wells;

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hydraulic fracturing;

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well production operations;

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disposal of produced water;

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regulation of transportation and sale of crude oil, natural gas, and natural gas liquids;

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surface usage;

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calculation and disbursement of royalty payments and production taxes; and

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restoration of properties used for oil and gas operations.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from crude oil and natural gas wells; and the unitization or pooling of oil and gas properties. Some states allow the forced pooling or unitization of tracts to facilitate exploration and development, while other states rely on voluntary pooling of lands and leases. Such rules often impact the ultimate timing of our exploration and development plans. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas. These regulations limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.

Certain of our leases are granted or approved by the federal government and administered by the Bureau of Land Management or Bureau of Indian Affairs of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. Moreover, the permitting process for oil and gas activities on federal and Indian lands can sometimes be subject to delay, including as a result of challenges to permits or other regulatory decisions brought by non-governmental organizations or other parties, which can hinder development activities or otherwise adversely impact operations. The federal government has, from time to time, evaluated and, in some cases, promulgated new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands.

For additional information on the Company’s regulatory risks, see Part 1, Item 1A. Risk Factors—Legal and Regulatory Risks of this report.

Human Capital

Employees and Labor Relations

As of December 31, 2024, we employed 1,395 people, all of which were employed in the United States, with 795 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 600 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, Montana, Wyoming, and Texas. None of our employees are subject to collective bargaining agreements. We believe our overall relations with our workforce are good.

Compensation

Because we operate in a highly competitive environment, we have designed our compensation program to attract, retain and motivate experienced, talented individuals. Our program is also designed to align employee’s interests with those of our owners and to reward them for achieving the business and strategic objectives determined to be important to help the Company create and maintain

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advantage in a competitive environment. We align our employee’s interests with those of our owners by making annual long-term incentive awards to virtually all of our salaried employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.

Safety

Safety is our highest priority and one of our core values. We promote safety with a robust health and safety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.

We encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel. We’ve established programs to recognize and reward Company employees and contractors who observe and report outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety culture and performance.

Training and Development

We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, operating the Continental Leadership Learning Center which offers numerous instructor-led programs designed to foster employee development and maintaining a learning management system which provides access to numerous technical and soft skills online courses. We also invest time and resources in supporting the creation of individual development plans for our employees.

Health and Wellness

We offer various benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off, and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For instance, employees at our corporate headquarters have access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, and smoking cessation programs to encourage total body wellness.

Diversity and Inclusion

We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, sexual orientation, gender identity, national origin, political affiliation, age, disability, genetic information, veteran status, or any other basis protected by local, state, or federal law. We also maintain a robust compliance program rooted in our Code of Business Conduct, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities.

Company Contact Information

Our corporate internet website is www.clr.com. Through the “Stakeholders” section of our website, we make available free of charge reports filed with or furnished to the SEC. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.

We electronically file periodic reports with the SEC as required by our senior note indentures. The SEC maintains an internet website that contains reports and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.

Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.

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Item 1A. Risk Factors

You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our debt securities. If any of the following risks develop into actual events, our business, financial condition, results of operations, or cash flows could be materially adversely affected.

Business and Operating Risks

Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.

The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable and commodity prices will likely remain volatile in the future.

The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

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worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;

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the actions of the Organization of Petroleum Exporting Countries (“OPEC”) and other petroleum producing nations;

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the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws as well as regulations governing the imposition of trade restrictions and foreign and domestic tariffs;

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executive, regulatory or legislative actions by Congress, the Presidential Office, or states in which we operate;

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geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;

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the level of global, national, and regional crude oil and natural gas exploration and production activities;

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the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;

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the level and effect of speculative trading in commodity futures markets;

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the relative strength of the United States dollar compared to foreign currencies;

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the price and quantity of imports of foreign crude oil;

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the price and quantity of exports of crude oil or liquefied natural gas from the United States;

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military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations, including the continuation of, or any increase in the severity of, conflicts in Ukraine or the Middle East;

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localized supply and demand fundamentals;

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the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;

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adverse climatic conditions, natural disasters, and national and global health epidemics and concerns;

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technological advances affecting energy production and consumption;

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the effect of worldwide energy conservation and greenhouse gas emission limitations or other environmental protection efforts;

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the impact arising from increasing attention to environmental, social, and governance (“ESG”) matters; and

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the price and availability of alternative fuels or other energy sources.

Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.

In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our

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estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.

Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.

Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase borrowing costs under our revolving credit facility, and limit our ability to access debt capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to meet our capital expenditure needs and commitments.

The ability or willingness of Saudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to set and maintain production levels has a significant impact on crude oil prices.

OPEC is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production targets, agree to further production targets in the future, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our future financial condition and results of operations depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.

Our management has specifically identified prospects and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of risks and uncertainties as described herein. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail our drilling and completion activities. Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. Because of these uncertainties, we do not know if our potential drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return.

Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.

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Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:

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abnormal pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment or qualified personnel;

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shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;

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delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;

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mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;

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restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;

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political events, public protests, civil disturbances, terrorist acts or cybersecurity attacks;

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decreases in, or extended periods of low, crude oil and natural gas prices;

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title issues;

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environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;

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adverse climatic conditions and natural disasters;

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spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;

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limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and

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delays imposed by or resulting from compliance with regulatory requirements including permitting.

Any of the above risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

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injury or loss of life;

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damage to or destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations;

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repair and remediation costs; and

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litigation.

We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.

Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.

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Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company's current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.

The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves as of December 31, 2024.

In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data projected into the future, about crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.

Actual future production, crude oil and natural gas sales prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and natural gas prices and other factors, some of which are beyond our control.

In addition, the development of our proved undeveloped reserves may take longer than anticipated and may not be ultimately developed or produced. At December 31, 2024, approximately 47% of our total estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2024 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $9.8 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we may be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and may in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period.

Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 28% of our total net undeveloped acreage at December 31, 2024.

Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.

Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.

The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some

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contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we will be unable to realize revenue from those wells until other arrangements are made for the sale or delivery of our products and acreage lease terminations could result if production is shut-in for a prolonged period.

The disruption of transportation, processing, refining, or export facilities due to contractual disputes or litigation, labor disputes, maintenance, civil disturbances, international trade disputes, public protests, terrorist attacks, cybersecurity attacks, adverse climatic events, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies or tariffs, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on prices in the areas we operate. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.

Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues.

The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We monitor and adjust our capital spending plans upward or downward depending on market conditions. Our 2025 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:

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the prices at which crude oil and natural gas are sold;

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the volume of our proved reserves;

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the volume of crude oil and natural gas we are able to produce and sell from existing wells; and

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our ability to acquire, locate and produce new reserves;

If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or seek financing in banking or debt capital markets to fund our operations.

We have a revolving credit facility with lender commitments totaling $1.80 billion that matures in October 2029. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute debt capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.

In the regions in which we operate, there have been shortages of drilling rigs, well completion crews, equipment, personnel, field services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.

The demand for qualified and experienced field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices or supply chain disruptions, causing periodic shortages and/or higher costs. Any of these factors may cause costs to rise which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.

While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in new or emerging areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage in the emerging areas may decline if drilling results are unsuccessful.

We have limited control over the activities on properties we do not operate.

Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2024, non-operated properties represented 12% of our estimated proved developed reserves, 5% of our estimated proved undeveloped reserves, and 9% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.

As part of our business strategy, we have made and expect to continue making acquisitions of oil and gas properties, divest assets, and enter into joint development arrangements. The successful acquisition of oil and gas properties requires an assessment of several factors, including but not limited to:

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reservoir modeling and evaluation of recoverable reserves;

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future crude oil and natural gas prices and location and quality differentials;

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the quality of the title to acquired properties;

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the ability to access future drilling locations;

•

availability and cost of gathering, processing, and transportation facilities;

•

availability and cost of drilling and completion equipment and of skilled personnel;

•

future development and operating costs and potential environmental and other liabilities; and

•

regulatory, permitting and similar matters.

The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties

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may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Significant acquisitions and other strategic transactions may involve other risks that may impact our business, including:

•

diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

•

the challenge and cost of integrating acquired assets and operations with our preexisting assets and operations while carrying on our ongoing business; and

•

the failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

As a result of our strategy of assessing and executing on accretive acquisitions, the size and geographic footprint of our business has increased and may continue to do so, including into new jurisdictions. Our future success will depend, in part, on our ability to manage our expanded business, which may pose challenges including those related to the management and monitoring of new operations and basins and associated increased costs and complexity. We believe our acquisitions will complement our business strategies by delivering enhanced cash flows and corporate returns, among other things. However, the anticipated benefits of the transactions may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits within anticipated timing or at all, our business, financial condition and operating results may be adversely affected.

In addition, from time to time we may sell or otherwise dispose of certain assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.

Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty, geopolitical events, international trade disputes and domestic and foreign tariffs, and health epidemics could adversely impact our business.

United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, inflation, changing economic sanctions, health-related concerns, and currency volatility. These global macroeconomic conditions may have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Trade restrictions or other governmental actions related to domestic and foreign tariffs or trade policies have impacted in the past, and have the potential to further impact, our business and industry by increasing the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities. Furthermore, tariffs and any quantitative import restrictions, particularly those impacting the cost and availability of steel and aluminum, and certain manufactured production equipment, may cause disruption in the energy industry's supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted in the past, and have the potential to further impact, domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.

A cybersecurity incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business and industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We rely heavily on digital technologies, including information and operational systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily dependent on digital technology.

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As dependence on digital technologies has increased, cybersecurity incidents, including deliberate attacks or unintentional events, have also evolved and increased in frequency. Cybersecurity attacks are becoming more sophisticated and include, but are not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic synthetic media generated by artificial intelligence), ransomware attacks, attempts to gain unauthorized access to data, and other electronic security breaches. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cybersecurity attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data, interruption of operating activities, challenges in maintaining our books and records, environmental damage, communication interruptions or other disruptions of our business operations. For example, there have been well-publicized cases in recent years involving cybersecurity attacks on software vendors utilized by the Company. In response to those incidents, we deployed our cybersecurity incidence response protocols and took steps to contain and remediate potential vulnerabilities. As of the date of this report, we are not aware of any material compromises to our operations as a result of the attacks; however, other similar attacks in the future could have a significant negative impact on our systems and operations.

A cybersecurity attack involving our information or operational systems and related infrastructure, and/or that of our business associates and customers, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access to, or theft of, confidential, sensitive or proprietary information, data corruption, interruption of operating activities, challenges in maintaining our books and records, environmental damage, communication interruptions or operational disruption that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, legal claims or proceedings, litigation costs, regulatory investigations and enforcement, penalties and fines, increased costs for compliance requirements or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, certain cybersecurity incidents such as reconnaissance of our systems and those of our business associates, may remain undetected for an extended period, which could result in significant consequences. We do not maintain specialized insurance for possible liability resulting from cybersecurity attacks due to lack of coverage for what we consider sensitive and proprietary data.

While the Company maintains cybersecurity systems and controls, disclosure controls and procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss. No security measure is infallible.

As of the date of this report, we do not believe that the Company has experienced any material losses relating to cybersecurity attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of a breach of our systems or those of our business associates. As cybersecurity threats continue to evolve, we may be required to expend significant additional resources to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cybersecurity attacks has resulted in evolving legal and compliance matters which may impose significant costs that may increase over time.

Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.

Our ability to acquire additional prospects and find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our inability to effectively compete in this environment could have a material adverse effect on our financial condition, results of operations and cash flows.

Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, fires, and ice storms affecting the areas in which we operate, including our corporate headquarters, could cause disruptions and in some cases suspension of our or our third party service providers' operations, which could have a material adverse effect on our business. Our planning for normal climatic variation, natural disasters, insurance programs and emergency recovery plans may inadequately mitigate the effects of such climatic conditions, and not all such effects can be predicted, eliminated or insured against. Longer term changes in temperature and precipitation patterns may result in changes to the amount, timing, or location of demand for

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energy or our production. While we consider these factors in our disaster preparedness and response and business continuity planning, we may not consider or prepare for every eventuality in such planning.

Financial Risks

Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions, the violation of which could adversely affect our business, financial condition and results of operations.

Our revolving credit facility contains restrictive covenants with which we must comply, including covenants that limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement. At December 31, 2024, we had $20 million of outstanding borrowings and $1.78 billion of available borrowing capacity on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.26.

The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.

Our ability to comply with the provisions of our revolving credit facility or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.

The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.

Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.2 billion in receivables at December 31, 2024) and our joint interest and other receivables ($382 million at December 31, 2024). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.

Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A prolonged worsening of commodity prices may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.

Legal and Regulatory Risks

Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a summary of certain significant environmental and occupational safety and health legal requirements that govern us. Such requirements include those pertaining to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of, or more stringent limitations upon, new leasing and permitting on federal lands and waters; hydraulic fracturing; waste water disposal; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows. In addition, because public policy changes affecting

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the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended, repealed, or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations.

We are subject to certain complex federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health that could result in increased costs, operating restrictions or delays, limitations or prohibitions on our ability to develop and produce reserves, or expose us to significant liabilities.

Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales and transport of crude oil, NGLs and natural gas, and employees and labor relations.

Failure to comply with laws and regulations, including those summarized in Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry, may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Changes in tax laws or tax rulings could materially affect our financial position, results of operations, and cash flows.

Rules and regulations governing U.S. federal, state, and local income taxation are continually under review and subject to change. It cannot be predicted if changes to current U.S. tax laws and regulations will be introduced as legislation or, if introduced, later enacted and, if enacted, what form such enacted legislation would take. While certain changes to tax laws and regulations may negatively impact our business, certain changes may be beneficial.

Our operations and the operations of our customers are subject to a number of risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas we produce.

Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, variability in power generation output from alternative energy facilities that are dependent on weather conditions, such as wind and solar, may result in intermittent changes in demand for the commodities we produce which could lead to increased volatility in commodity prices. One or more of these developments could have an adverse effect on our assets and operations.

Scrutiny on environmental, social, and corporate governance matters may impact our business.

Companies across all industries are facing scrutiny from a wide array of stakeholders related to their ESG practices. ESG standards are evolving and if we are perceived to have not responded appropriately to certain standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business or financial condition, could be materially and adversely affected. Attention to climate change, societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to recruit necessary talent, and our access to debt capital markets.

Institutional lenders who provide financing for fossil fuel energy companies may become more attentive to lending practices that favor power sources such as wind and solar and some of them may elect not to provide funding for fossil fuel energy companies or impose certain ESG-related targets or goals as a condition to funding. While we cannot predict what polices may result from these developments, such efforts could make it more difficult for fossil fuel companies to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or other aspects of our business.

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Item 1B. Unresolved Staff Comments

Not applicable.

Item 1C. Cybersecurity

Our business and industry has become increasingly dependent upon digital technologies, including information and operational systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. We recognize the importance of developing, implementing, and maintaining effective cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data. The Company has an Insider Threat and Data Loss Prevention program that is designed to protect the confidentiality, integrity and availability of such data, and we maintain processes designed to assess, identify, and manage material risks from cybersecurity threats.

The Company has a cybersecurity team with relevant subject-matter expertise that is part of the Company’s Information Technology department (the “Cybersecurity Team”). This team reports to the Company’s Vice President and Chief Information Officer (“CIO”) and is led by the Company’s Chief Information Security Officer (“CISO”), who has primary responsibility for oversight of the Company’s assessment, identification, and management of cybersecurity risks. The CIO and CISO jointly determine whether a given cybersecurity matter is sufficiently important to warrant elevating it to the attention of the Company’s Cybersecurity Executive Committee (defined below) and/or Board of Directors. Our CISO has received certifications relating to information security, security leadership, and forensics from the Global Information Assurance organization.

The Cybersecurity Team monitors the cybersecurity environment for threats and indicators of compromise. It also considers the risks attendant to the Company’s business operations and strategy and develops solutions and mitigation measures for the risks identified, including risks arising in connection with third-party interactions and the integration of newly acquired assets. In addition, the Company invests in Security Awareness training to help promote employee awareness of cybersecurity.

The Company’s internal cybersecurity efforts are supported by a team of outside consultants, assessors, and third-party vendors who assist with identifying and monitoring risks and indications of compromise.

The Cybersecurity Team regularly engages third-party assessors to conduct evaluations of the Company’s cybersecurity risk mitigation efforts and strategy. The Company also engages a third-party auditing firm to periodically assess our information security program. Audits are also conducted from time-to-time by other third parties, such as insurance adjusters and regulators.

The Cybersecurity Team engages third-party vendors to assist with managing endpoint security, managing the Company’s security operations center, providing threat detection and response capabilities, monitoring certain operational technology and control system environments, and providing threat detection and vulnerability identification and remediation services. Additionally, the Company is a member of the Oil and Natural Gas Information and Analysis Center. This center provides the Company with information regarding threats to the oil and gas industry and threats reported by other industry participants. Finally, the Cybersecurity Team periodically engages with the cybersecurity-related guidance of other third parties such as law enforcement, industry trade groups and vendors.

The Cybersecurity Team reviews the integrity of services provided by vendors engaged to support the Company’s cybersecurity efforts using the same methods as are used to evaluate the services provided by other vendors engaged to support the Company’s regular business operations.

The above cybersecurity risk management processes are integrated into the Company’s overall enterprise risk management program. Cybersecurity risks are understood to be significant business risks, and as such, are considered an important component of our enterprise-wide risk management approach.

Since the Company is private, it has no independent members of its Board of Directors. All of the Company’s directors are also executive officers. The body primarily responsible for oversight of the Cybersecurity Team is the Cybersecurity Executive Committee, which is composed of the Company’s President and Chief Executive Officer; Executive Vice President, Chief Culture Officer and Administrative Officer (both of whom are also members of the Company’s Board of Directors); Chief Financial Officer and Executive Vice President of Strategic Planning; Senior Vice President, General Counsel and Secretary; CIO; and the Director of Corporate Security. The Cybersecurity Executive Committee meets regularly and during these meetings its members review and discuss cybersecurity information provided by the CISO, which may include: (i) metrics relevant to cybersecurity issues; (ii) summaries of changes or proposed changes to the Company’s cybersecurity program; and (iii) cybersecurity risk and threat updates. Information regarding any critical cybersecurity-related matter is communicated to the Cybersecurity Executive Committee as soon as practicable.

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In addition, the CISO periodically briefs the Company's Audit Committee regarding cybersecurity matters at a regularly scheduled committee meeting and these briefings cover the same types of information as is presented to the Cybersecurity Executive Committee. The Audit Committee is composed of the two members of the Board of Directors who are also members of the Cybersecurity Executive Committee.

The Company has developed a Cybersecurity Incident Response Plan (the “Response Plan”), which is based upon NASA’s mission control incident response procedures to address and manage certain cybersecurity incidents. If an incident meets certain criteria, the incident response plan is invoked by the CISO and General Counsel. Once the plan is invoked, an impact assessment is conducted and a remediation plan is developed, if needed. The plan also sets forth procedures for monitoring incidents and post-incident follow-up so that any lessons learned can be discussed. Where appropriate, the post-incident follow up identifies measures that can be implemented to aid with future incident prevention and detection. Under the Response Plan any incident-related information is communicated using the channels outlined in the Response Plan.

As of the date of this report, though the Company and our service providers have experienced certain cybersecurity incidents, the Company does not believe any prior cybersecurity threat or incident has materially affected or are reasonably likely to materially affect the Company, including its business operations or prospects. However, the Company acknowledges that cybersecurity threats are continually evolving and the possibility of future cybersecurity incidents remains. Despite the implementation of our cybersecurity processes, our security measures cannot guarantee that a significant cyberattack will not occur. A successful attack on our information technology systems could have significant consequences for the business. While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security. No security measure is infallible. For additional information about the risks to our business associated with cybersecurity incidents, please see “A cybersecurity incident could result in information theft, data corruption, operational disruption, and/or financial loss” under Part I, Item IA. Risk Factors.

Item 2. Properties

The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.

Item 3. Legal Proceedings

We are involved in various legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, claims made by former shareholders in connection with our take-private transaction, antitrust claims related to the market price of hydrocarbons, personal injury claims, regulatory compliance matters, disputes with tax authorities and other matters. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

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Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Effective November 22, 2022, Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding at the time of this filing.

The Company has no dividend policy and currently has no plans to pay cash dividends in the future year.

Item 6. Reserved

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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes included elsewhere in this report. Results attributable to noncontrolling interests are not material relative to consolidated results and are not separately presented or discussed below.

The following discussion and analysis includes forward-looking statements and should be read in conjunction with Part I, Item 1A. Risk Factors in this report, along with Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995 at the beginning of this report, for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

Overview

We are an independent crude oil and natural gas company engaged in the exploration, development, management, and production of crude oil and natural gas and associated products with properties primarily located in four leading basins in the United States – the Bakken field of North Dakota and Montana, the Anadarko Basin of Oklahoma, the Permian Basin of Texas, and the Powder River Basin of Wyoming. Additionally, we pursue the acquisition and management of perpetually owned minerals located in certain of our key operating areas. We derive the majority of our operating income and cash flows from the sale of crude oil, natural gas, and natural gas liquids and expect this to continue in the future. As discussed in Part II. Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies—2022 Take-Private Transaction, effective November 22, 2022 Continental Resources, Inc. became a privately held corporation and has no publicly available common shares outstanding.

Financial and Operating Metrics

Commodity prices have remained volatile due to various factors, some of which include global supply and demand, global inventory levels, and regional conflicts. Average NYMEX oil prices for the years ended December 31, 2024, 2023, and 2022 were $75.75, $77.57, and $94.17, respectively. Average NYMEX gas prices for the years ended December 31, 2024, 2023, and 2022 were $2.26, $2.73, and $6.72, respectively. The following table contains financial and operating metrics for the periods presented. Average sales prices exclude any effect of derivative transactions. Per-unit expenses have been calculated using sales volumes.


	Year ended December 31,
	2024			2023			2022
Average daily production:
Crude oil (Bbl per day)		229,889			232,083			199,526
Natural gas (Mcf per day) (1)		1,176,638			1,248,488			1,213,643
Crude oil equivalents (Boe per day)		425,995			440,164			401,800
Average sales prices:
Crude oil ($/Bbl)	$	75.18		$	76.89		$	94.95
Natural gas ($/Mcf) (1)	$	2.16		$	2.60		$	7.15
Production expenses ($/Boe)	$	4.94		$	4.47		$	4.24
Production and ad valorem taxes (% of net crude oil and natural gas sales)		8.1	%		8.2	%		7.5	%
DD&A ($/Boe)	$	15.93		$	14.11		$	12.86
Total general and administrative expenses ($/Boe)	$	1.69		$	1.74		$	2.74

(1)

Natural gas production volumes, sales volumes, and sales prices presented throughout management's discussion and analysis reflect the combined value for natural gas and natural gas liquids.

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Results of Operations

The following table presents selected financial and operating information for the periods presented.


	Year Ended December 31,
In thousands	2024			2023			2022
Crude oil, natural gas, and natural gas liquids sales	$	7,256,685		$	7,684,263		$	10,074,675
Gain (loss) on derivative instruments, net		27,168			943,768			(671,095	)
Crude oil and natural gas service operations		93,776			103,710			70,128
Total revenues		7,377,629			8,731,741			9,473,708
Operating costs and expenses		(4,623,931	)		(4,419,008	)		(4,120,028	)
Other expenses, net		(265,131	)		(383,786	)		(285,267	)
Income before income taxes		2,488,567			3,928,947			5,068,413
Provision for income taxes		(471,849	)		(827,630	)		(1,020,804	)
Income before equity in net loss of affiliate		2,016,718			3,101,317			4,047,609
Equity in net loss of affiliate		(3,653	)		(3,129	)		(1,489	)
Net income		2,013,065			3,098,188			4,046,120
Net income attributable to noncontrolling interests		1,287			2,361			21,562
Net income attributable to Continental Resources	$	2,011,778		$	3,095,827		$	4,024,558

Production volumes:
Crude oil (MBbl)		84,139			84,710			72,827
Natural gas (MMcf)		430,649			455,698			442,980
Crude oil equivalents (MBoe)		155,914			160,660			146,657
Sales volumes:
Crude oil (MBbl)		84,167			84,508			72,732
Natural gas (MMcf)		430,649			455,698			442,980
Crude oil equivalents (MBoe)		155,942			160,457			146,562

Year ended December 31, 2024 compared to the year ended December 31, 2023

Below is a discussion of changes in our results of operations for 2024 compared to 2023. A discussion of changes in our results of operations for 2023 compared to 2022 has been omitted from this Form 10-K, but may be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Form 10-K for the year ended December 31, 2023 as filed with the SEC on February 22, 2024.

Production

The following table summarizes the changes in our average daily Boe production by major operating area for the periods presented.


	Fourth Quarter							Year Ended December 31,
Boe production per day	2024		2023		% Change			2024		2023		% Change
Bakken		189,787		220,428		(14	)%		194,606		202,610		(4	)%
Anadarko Basin		126,068		144,158		(13	)%		132,558		153,426		(14	)%
Powder River Basin		27,215		25,577		6	%		24,979		23,757		5	%
Permian Basin		74,334		58,601		27	%		68,589		54,651		26	%
All other		5,061		5,666		(11	)%		5,263		5,720		(8	)%
Total		422,465		454,430		(7	)%		425,995		440,164		(3	)%

The following table summarizes the changes in our production by product for the periods presented.


	Year Ended December 31,													Volume
	2024					2023					Volume			percent
	Volume		Percent			Volume		Percent			decrease			decrease
Crude oil (MBbl)		84,139		54	%		84,710		53	%		(571	)		(1	)%
Natural gas (MMcf)		430,649		46	%		455,698		47	%		(25,049	)		(5	)%
Total (MBoe)		155,914		100	%		160,660		100	%		(4,746	)		(3	)%

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The 1% decrease in crude oil production and 5% decrease in natural gas production in 2024 compared to 2023 were primarily driven by natural declines in production coupled with planned moderation in capital spending, asset divestitures and variation in the timing of new well completions between years.

Revenues

Our revenues consist of sales of crude oil, natural gas, and natural gas liquids, gains and losses resulting from changes in the fair value of our derivative instruments, and revenues associated with crude oil and natural gas service operations.

Crude oil, natural gas, and natural gas liquids sales. Sales for 2024 totaled $7.26 billion, a 6% decrease compared to sales of $7.68 billion for 2023 due to decreases in sales prices coupled with a decrease in sales volumes as discussed below.

Total sales volumes for 2024 decreased 4,515 MBoe, or 3%, compared to 2023 primarily due to the previously described decrease in natural gas production volumes. For 2024, our crude oil sales volumes were consistent with 2023 while our natural gas sales volumes decreased 5% compared to 2023.

Our crude oil sales prices averaged $75.18 per barrel for 2024, a decrease of 2% compared to $76.89 per barrel for 2023 due to a decrease in market prices resulting from changes in various macroeconomic conditions between periods.

Our natural gas sales prices averaged $2.16 per Mcf for 2024, a decrease of 17% compared to $2.60 per Mcf for 2023 due to a decrease in market prices for residue gas and natural gas liquids.

Derivatives. Changes in settled and future commodity prices in 2024 had a net favorable impact on the fair value of our derivatives, which resulted in positive revenue adjustments of $27.2 million for the year, representing $377.6 million of realized cash gains partially offset by $350.4 million of unsettled non-cash losses, compared to positive revenue adjustments totaling $943.8 million in 2023.

Crude oil and natural gas service operations. Our crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, delivery, and disposal activities, which are impacted by our production volumes and the timing and extent of our drilling and completion projects. Revenues associated with such activities decreased $9.9 million, or 10%, from $103.7 million for 2023 to $93.8 million for 2024 due to decreased water handling activities resulting from decreases in completion activities and production volumes compared to 2023.

Operating Costs and Expenses

Production expenses. Production expenses increased $53.4 million, or 7%, to $770.9 million for 2024 compared to $717.5 million for 2023 due to an increase in the number of producing wells from drilling and completion activities, costs associated with adverse winter weather conditions in the Bakken and Powder River Basin in the 2024 first quarter, and higher workover-related activities aimed at enhancing production from producing properties. Production expenses on a per-Boe basis averaged $4.94 per Boe for 2024 compared to $4.47 per Boe for 2023.

Production and ad valorem taxes. Production and ad valorem taxes decreased $47.4 million, or 8%, to $556.2 million for 2024 compared to $603.5 million for 2023 due to the previously described decrease in crude oil, natural gas, and NGL sales. Our production taxes as a percentage of net sales averaged 8.1% for 2024 compared to 8.2% for 2023.

Transportation, gathering, processing, and compression. These charges increased $29.0 million, or 9%, to $367.2 million for 2024 compared to $338.2 million for 2023 due to changes in marketing terms and arrangements utilized between periods and an increase in our working interest share of cost burdens in certain operating areas.

Depreciation, depletion, amortization and accretion (“DD&A”). Total DD&A amounted to $2.48 billion for 2024, an increase of $219.1 million, or 10%, compared to $2.26 billion for 2023, due to an increase in our DD&A rate per Boe as further discussed below. The following table shows the components of our DD&A on a unit of sales basis for the periods presented.


	Year ended December 31,
$/Boe	2024		2023
Crude oil and natural gas properties	$	15.26	$	13.58
Other equipment		0.53		0.44
Asset retirement obligation accretion		0.14		0.09
Depreciation, depletion, amortization and accretion	$	15.93	$	14.11

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Estimated proved reserves are a key component in our computation of DD&A expense. Proved reserves are determined using the unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months as required by SEC rules. Holding all other factors constant, if proved reserves are revised downward due to commodity price declines or other reasons, the rate at which we record DD&A expense increases. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense decreases.

Our proved reserves have been revised downward over the past year prompted by decreases in rolling twelve-month average SEC commodity prices and other factors, which contributed to an increase in our DD&A rate for crude oil and natural gas properties in 2024 compared to 2023 along with variation in the mix of sales volumes across the Company's operating areas between periods.

Property impairments. Property impairments decreased $23.6 million to $43.2 million for 2024 compared to $66.8 million for 2023 due in part to $15.5 million of proved property impairments recognized in 2023 compared to no proved property impairments being recognized in 2024. Additionally, impairments of unproved properties decreased $8.1 million in 2024 compared to 2023 reflecting a decrease in the amortization of undeveloped leasehold costs over the past year.

General and administrative (“G&A”) expenses. G&A expenses decreased $15.3 million, or 5%, to $264.0 million for 2024 compared to $279.3 million for 2023. Total G&A expenses include charges for long-term incentive compensation awards of $83.7 million for 2024 compared to $91.3 million for 2023. G&A expenses other than incentive compensation awards totaled $180.3 million for 2024, a decrease of $7.6 million, or 4%, compared to $188.0 million for 2023 primarily due to higher overhead and cost recoveries from joint interest owners compared to 2023.

The following table shows the components of G&A expenses on a unit of sales basis for the periods presented.


	Year ended December 31,
$/Boe	2024		2023
General and administrative expenses	$	1.15	$	1.17
Long-term incentive compensation awards		0.54		0.57
Total general and administrative expenses	$	1.69	$	1.74

Interest expense. Interest expense decreased $120.0 million, or 30%, to $275.7 million for 2024 compared to $395.8 million for 2023 due to a decrease in our annual weighted average outstanding debt balance from $7.9 billion in 2023 to $5.8 billion in 2024. This decrease was driven by debt reduction throughout 2024, including the reduction of credit facility borrowings, the repayment of our $750 million term loan, and the redemption of our $893 million of 2024 Notes. Our outstanding debt totaled $4.8 billion at December 31, 2024.

Income Taxes. We provided for income taxes at a combined federal and state tax rate of 23.5% for both 2024 and 2023. We recorded income tax provisions of $471.8 million and $827.6 million for 2024 and 2023, respectively, which resulted in effective tax rates of 19.0% and 21.1%, respectively, after taking into account the application of statutory tax rates, permanent taxable differences, estimated tax credits, and other items. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 11. Income Taxes for a summary of the sources and tax effects of items comprising our income tax provision and resulting effective tax rates for 2024 and 2023.

Liquidity and Capital Resources

Our primary sources of liquidity have historically been cash flows generated from operating activities, financing provided by our credit facility and the issuance of debt securities. Additionally, asset dispositions and joint development arrangements have provided a source of cash flow for use in reducing debt and enhancing liquidity.

At February 1, 2025, we had $1.8 billion of borrowing availability under our credit facility. Our credit facility, which is unsecured and has no borrowing base subject to redetermination, does not mature until October 2029.

Based on our planned capital spending, our forecasted cash flows, and projected levels of indebtedness, we expect to maintain compliance with the covenants under our credit facility and senior note indentures. Further, based on current market indications, we expect to meet our contractual cash commitments to third parties subsequently described under the heading Future Capital Requirements, recognizing we may be required to meet such commitments even if our business plan assumptions were to change. We monitor our capital spending closely based on actual and projected cash flows and have the ability to reduce spending or dispose of assets if needed to preserve liquidity and financial flexibility to fund our operations.

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Cash Flows

Cash flows from operating activities

Net cash provided by operating activities decreased $422.2 million, or 8%, to $4.64 billion for 2024 compared to $5.06 billion for 2023. This decrease was driven by a $427.6 million decrease in crude oil, natural gas, and NGL revenues along with increases in certain cash operating expenses including a $53.4 million increase in production expenses, a $29.0 million increase in transportation, gathering, processing, and compression expenses, and a $139.2 million increase in cash payments for income taxes. These decreases in cash flows were partially offset by a $120.4 million improvement in realized cash settlements on matured commodity derivatives, a $116.8 million decrease in cash paid for interest, and a $47.4 million decrease in production and ad valorem taxes.

Cash flows used in investing activities

Net cash used in investing activities totaled $2.78 billion for 2024 compared to $3.56 billion for 2023. Our investing cash flows for 2024 included $3.03 billion of exploration and development costs compared to $3.55 billion of exploration and development costs for 2023, reflecting variation in the timing of our capital spending between periods. In addition, net cash used in investing activities was further decreased by lower acquisitions of producing crude oil and natural gas properties, with $9 million acquired in 2024 compared to $161 million acquired in 2023, as well as increased proceeds from the sale of assets with $546 million of proceeds received in 2024 compared to $390 million of proceeds received in 2023.

Cash flows from financing activities

Net cash used in financing activities for 2024 totaled $1.84 billion, primarily consisting of $190 million of net repayments on our credit facility, $893 million of cash used to redeem senior notes, and $752 million of cash used for the repayment of our term loan.

Net cash used in financing activities for 2023 totaled $1.61 billion, primarily consisting of $950 million of net repayments on our credit facility and $636 million of cash used to redeem senior notes.

Future Sources of Financing

Although we cannot provide any assurance, we believe funds from operating cash flows, our cash balance, and availability under our credit facility should be sufficient to meet our normal operating needs, debt service obligations, budgeted capital expenditures, and cash payments for income taxes for at least the next 12 months and to meet our contractual cash commitments to third parties described under the heading Future Capital Requirements beyond 12 months.

Based on current market indications supported by cash flow protection provided by our hedge portfolio against commodity price declines, our budgeted capital spending plans for 2025 are expected to be funded from operating cash flows. Any deficiencies in operating cash flows relative to budgeted spending are expected to be funded by borrowings under our credit facility. If cash flows are materially impacted by declines in commodity prices, we have the ability to reduce our capital expenditures or utilize the availability of our credit facility if needed to fund our operations.

We may choose to access banking or debt capital markets for additional financing or capital to fund our operations or take advantage of business opportunities that may arise. Further, we may sell assets or enter into strategic joint development opportunities in order to obtain funding if such transactions can be executed on satisfactory terms. However, no assurance can be given that such transactions will occur.

Credit facility

We have an unsecured credit facility, maturing in October 2029, with aggregate lender commitments totaling $1.8 billion. The commitments are from a syndicate of 14 banks and financial institutions. We believe each member of the current syndicate has the capability to fund its commitment.

The commitments under our credit facility are not dependent on a borrowing base calculation subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants.

Our credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, or merge, consolidate or sell all or substantially all of our assets. Our credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. See

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Part II, Item 8. Notes to Consolidated Financial Statements—Note 8. Debt for a discussion of how this ratio is calculated pursuant to our credit agreement.

We were in compliance with our credit facility covenants at December 31, 2024 and expect to maintain compliance. At December 31, 2024, our consolidated net debt to total capitalization ratio was 0.26. We do not believe the credit facility covenants are reasonably likely to limit our ability to undertake additional debt financing if needed to support our business.

Future Capital Requirements

Our material future cash requirements are summarized below. Based on current market indications, we expect to meet our contractual cash commitments to third parties as of December 31, 2024, recognizing we may be required to meet such commitments even if our business plan assumptions were to change.

Senior notes

Our debt includes outstanding senior note obligations totaling $4.8 billion at December 31, 2024, exclusive of interest payment obligations thereon. Our senior notes are not subject to any mandatory redemption or sinking fund requirements. The earliest scheduled senior note maturity is our $800 million of 2026 Notes due in November 2026. For further information on the face values, maturity dates, semi-annual interest payment dates, optional redemption periods and covenant restrictions related to our senior notes, refer to Note 8. Debt in Part II, Item 8. Notes to Consolidated Financial Statements.

We were in compliance with our senior note covenants at December 31, 2024 and expect to maintain compliance. We do not believe the senior note covenants will materially limit our ability to undertake additional debt financing. Downgrades or other negative rating actions with respect to the credit ratings assigned to our senior unsecured debt do not trigger additional senior note covenants.

Credit facility borrowings

As of February 1, 2025, we had no outstanding borrowings on our credit facility. Our credit facility matures in October 2029.

Transportation, gathering, and processing commitments

We have entered into transportation, gathering, and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities that require us to pay per-unit charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2024 under the arrangements amount to approximately $799 million. A portion of these future costs will be borne by other interest owners. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 13. Commitments and Contingencies for additional information.

Capital Expenditures

For the year ended December 31, 2024, we invested $3.27 billion in our capital program excluding $24.3 million of unbudgeted acquisitions, excluding $20.5 million of mineral acquisitions attributable to Franco-Nevada, and including $9.2 million of capital costs associated with increased accruals for capital expenditures as compared to December 31, 2023.

For 2025, our capital expenditures budget attributable to us is $2.83 billion. Costs of acquisitions and investments, such as those described in Note 18. Equity Investment in Part II, Item 8. Notes to Consolidated Financial Statements, are not included in our 2025 capital budget, with the exception of planned levels of spending for mineral acquisitions.

Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, operational process improvements, the availability of drilling and completion rigs and other services and equipment, cost inflation, the availability of transportation, gathering and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may adjust our spending should commodity prices materially change from current levels. We expect to continue participating as a buyer of properties when and if we have the ability to increase our position in strategic plays at attractive terms.

Cash Payments for Income Taxes

For the year ended December 31, 2024, we made cash payments for federal and state income taxes totaling $705.4 million, representing payments associated with 2023 tax return filing extensions and estimated quarterly payments for 2024 federal and state income taxes based on estimates of taxable income for 2024. Significant judgment is involved in estimating future taxable income as we are required to make assumptions about future commodity prices, projected production, development activities, capital spending,

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profitability, and general economic conditions, all of which are subject to material revision in future periods as better information becomes available. If commodity prices remain at current levels, we expect to continue generating significant taxable income through at least year-end 2025, which would result in us continuing to make estimated tax payments on a quarterly basis in 2025. Because of the significant uncertainty inherent in numerous factors utilized in projecting taxable income, we cannot predict the amount of future income tax payments with certainty.

Long-term incentive compensation awards

As discussed in Note 15. Incentive Compensation in Part II, Item 8. Notes to Consolidated Financial Statements we have recognized a current liability of $74.5 million and a non-current liability of $36.5 million in the consolidated balance sheets associated with unvested incentive compensation awards granted to employees that are scheduled to vest in 2025, 2026, and 2027. We intend to settle these awards in cash at the time vesting occurs. Our recognized liabilities will be remeasured each reporting period leading up to the applicable award vesting dates to reflect additional service rendered by employees and to reflect changes in expected cash payments arising from underlying changes in the value of the Company based on independent third party appraisals. The current liability at December 31, 2024 was paid in cash to employees in February 2025 upon the scheduled vesting of awards. We intend to grant additional awards on an annual basis that we plan to settle in cash upon vesting.

Stock redemption option

See Note 7. Fair Value Measurements—Stock Redemption Option in Part II, Item 8. Notes to Consolidated Financial Statements.

Delivery Commitments

We have various natural gas volume delivery commitments that are related to our key operating areas. We expect to primarily fulfill our contractual natural gas obligations with production from our proved reserves. However, we may purchase third-party volumes to satisfy our commitments. Additionally, in the Permian Basin certain of our firm sales contracts for crude oil include delivery commitments that specify the delivery of a fixed and determinable quantity. We expect to primarily fulfill our contractual crude oil obligations with production from our proved reserves. As of December 31, 2024, we were committed to deliver the following fixed quantities of natural gas and crude oil production. The volumes disclosed herein represent gross production associated with properties operated by us and do not reflect our net proportionate share of such amounts.


Year Ending	Natural Gas		Crude Oil
December 31,	Bcf		MMBo
2025		117		13
2026		99		3
2027		70		—
2028		30		—
2029		10		—
2030		10		—
2031		8		—

Senior note repurchases and redemptions

In recent years we have redeemed or repurchased a portion of our outstanding senior notes. From time to time, we may execute additional redemptions or repurchases of our senior notes for cash in open market transactions, privately negotiated transactions, or otherwise. The timing and amount of any such redemptions or repurchases will depend on prevailing market conditions, our liquidity and prospects for future access to capital, and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material.

Derivative Instruments

The fair value of our derivative instruments at December 31, 2024 was a net asset of $157.5 million. See Note 6. Derivative Instruments in Part II, Item 8. Notes to Consolidated Financial Statements for further discussion of our hedging activities, including a summary of derivative contracts in place as of December 31, 2024. The estimated fair value of our derivatives is highly sensitive to market price volatility and therefore subject to significant fluctuations from period to period. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for information on how hypothetical changes in commodity prices would impact the fair value of our derivatives as of December 31, 2024. Between January 1, 2025 and February 14, 2025 we entered into additional derivative instruments as summarized below.

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    Crude oil derivatives

    Weighted Average
Hedge Price ($/Bbl)

    Period and Type of Contract

    Average Volumes Hedged

    Roll Swaps

    Fixed Swaps

    January 2025 - December 2025

Fixed Swaps - WTI

52,000

Bbls/day

70.64

    February 2025 - December 2025

Roll Swaps - NYMEX

51,700

Bbls/day

0.94

Critical Accounting Policies and Estimates

Our consolidated financial statements and related footnotes contain information that is pertinent to our management’s discussion and analysis of financial condition and results of operations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and the disclosure and estimation of contingent assets and liabilities. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies and Note 9. Revenues for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used.

In management’s opinion, the most significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimations, revenue recognition, the choice of accounting method for crude oil and natural gas activities and derivatives, impairment of assets, income taxes and contingent liabilities. These areas are discussed below. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters and are believed to be reasonable under the circumstances. We evaluate our estimates and assumptions on a regular basis. Actual results could differ from the estimates as additional information becomes known.

Crude Oil and Natural Gas Reserves Estimation

Our external independent reserve engineers, Ryder Scott, and internal technical staff prepare the estimates of our crude oil and natural gas reserves and associated future net cash flows. Even though Ryder Scott and our internal technical staff are knowledgeable and follow authoritative guidelines for estimating reserves, they must make a number of subjective assumptions based on professional judgments in developing the reserve estimates. Estimates of reserves and their values, future production rates, and future costs and expenses are inherently uncertain for various reasons, including many factors beyond the Company’s control. Reserve estimates are updated annually and take into account recent production levels and other technical information about each of our properties.

Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions or removals of estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, changes in business strategies, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered. We cannot predict the amounts or timing of future reserve revisions or removals.

Estimates of proved reserves are key components of the Company’s most significant financial estimates including the computation of depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. Holding all other factors constant, if proved reserves are revised downward, the rate at which we record DD&A expense would increase, reducing net income. Conversely, if proved reserves are revised upward, the rate at which we record DD&A expense would decrease. Future revisions of reserves may be material and could significantly alter future depreciation, depletion, and amortization expense and may result in material impairments of assets.

Our DD&A calculations for oil and gas properties are performed on a field basis and revisions to proved reserves will not necessarily be applied ratably across all fields and may not be applied to some fields at all. Further, reserve revisions in significant fields may individually affect our DD&A rate. As a result, the impact on DD&A expense from revisions in reserves cannot be predicted with certainty and may result in changes in expense that are greater or less than the underlying changes in reserves.

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Revenue Recognition

We derive substantially all of our revenues from the sale of crude oil, natural gas, and NGLs. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 9. Revenues for discussion of our accounting policies governing the recognition and presentation of revenues.

Operated crude oil, natural gas, and NGL revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. For non-operated properties, the Company's proportionate share of production is generally marketed at the discretion of the operators. Non-operated revenues are recognized by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive.

At the end of each month, to record revenues we estimate the amount of production delivered and sold to customers and the prices at which they were sold. Variances between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received and are reflected in our financial statements as crude oil and natural gas sales. These variances have historically not been material.

For the sale of crude oil, natural gas, and NGLs we evaluate whether we are the principal, and report revenues on a gross basis (revenues presented separately from associated expenses), or an agent, and report revenues on a net basis. In this assessment, we consider if we obtain control of the products before they are transferred to the customer as well as other indicators. Judgment may be required in determining the point in time when control of products transfers to customers.

Successful Efforts Method of Accounting

Our business is subject to accounting rules that are unique to the crude oil and natural gas industry. Two generally accepted methods of accounting for oil and gas activities are available—the successful efforts method and the full cost method. The most significant differences between these two methods are the treatment of exploration costs and the manner in which the carrying value of oil and gas properties are amortized and evaluated for impairment. We use the successful efforts method of accounting for our oil and gas properties. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 1. Organization and Summary of Significant Accounting Policies for further discussion of the accounting policies applicable to the successful efforts method of accounting.

Derivative Activities

From time to time we utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of future production and for other purposes. We have elected not to designate any of our price risk management activities as cash flow hedges. As a result, we mark our derivative instruments to fair value and recognize the changes in fair value in current earnings.

In determining the amounts to be recorded for outstanding derivative contracts, we are required to estimate the fair value of the derivatives. We use an independent third party to provide our derivative valuations. The third party’s valuation models for derivative contracts are industry-standard models that consider various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The fair value calculations for collars requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the derivative agreements and the resulting estimated future cash inflows or outflows over the lives of the derivatives are discounted to calculate the fair value of the derivative contracts. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

We validate our derivative valuations through management review and by comparison to our counterparties’ valuations for reasonableness. Differences between our fair value calculations and counterparty valuations have historically not been material.

Impairment of Assets

All of our long-lived assets are monitored for potential impairment when circumstances indicate the carrying value of an asset may be greater than its future net cash flows, including cash flows from risk-adjusted proved reserves. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable.

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Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis. If the carrying amount of a field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value using a discounted cash flow model. For producing properties, the impairment evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for crude oil and natural gas, future costs to produce those products, estimates of future crude oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a field for impairment may result from significant declines in sales prices or downward revisions or removals of crude oil and natural gas reserves. Estimates of anticipated sales prices and recoverable reserves are highly judgmental and are subject to material revision in future periods.

No impairments were recognized for our proved crude oil and natural gas properties for the year ended December 31, 2024 as estimated future cash flows were determined to be in excess of cost basis. Commodity price assumptions used for the year-end December 31, 2024 impairment calculations were based on publicly available average annual forward commodity strip prices through year-end 2029 and were then escalated at 3% per year thereafter. Holding all other factors constant, as forward commodity prices decrease, our probability for recognizing producing property impairments may increase, or the magnitude of impairments to be recognized may increase. Conversely, as forward commodity prices increase, our probability for recognizing producing property impairments may decrease, or the magnitude of impairments to be recognized may decrease or be eliminated. As of December 31, 2024, the publicly available forward commodity strip prices for the year 2029 used in our fourth quarter impairment calculations averaged $63.01 per barrel for crude oil and $3.58 per Mcf for natural gas. If forward commodity prices materially decrease from current levels for an extended period, impairments of producing properties may be recognized in the future. Because of the uncertainty inherent in the numerous factors utilized in determining the fair value of producing properties, we cannot predict the timing and amount of future impairment charges, if any.

Impairment losses for unproved properties are generally recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management. The estimated timing and rate of successful drilling is highly judgmental and is subject to material revision in future periods as better information becomes available.

Income Taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. We apply judgment to determine the weight of both positive and negative evidence in order to conclude whether a valuation allowance is necessary for our deferred tax assets. In determining whether a valuation allowance is required, we consider, among other factors, our financial position, results of operations, projected future taxable income, reversal of existing deferred tax liabilities against deferred tax assets, and tax planning strategies. Significant judgment is involved in this determination as we are required to make assumptions about future commodity prices, projected production, development activities, profitability of future business strategies and forecasted economics in the oil and gas industry. Additionally, changes in the effective tax rate resulting from changes in tax law and our level of earnings may limit utilization of deferred tax assets and may affect the valuation of deferred tax balances in the future. Changes in judgment regarding future realization of deferred tax assets may result in a reversal of all or a portion of a valuation allowance. We believe our deferred tax assets at December 31, 2024 will ultimately be realized. We will continue to evaluate both the positive and negative evidence on a quarterly basis in determining the need for a valuation allowance with respect to our deferred tax assets.

We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. Our federal and state income tax returns are generally not prepared or filed before our consolidated financial statements are prepared; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax rate changes, tax credits, and net operating loss carryforwards, among other things. Adjustments related to these estimates are recorded in our tax provision in the period in which we file our income tax returns. Accordingly, our effective tax rate is subject to variability from period to period as a result of factors other than changes in federal and state tax rates and/or changes in tax laws which can affect tax-paying companies. For instance, our effective tax rate is affected by, among other things, permanent taxable differences, tax credits, valuation allowances, and changes in the apportionment of property, revenues, and payroll between states in which we own property as rates vary from state to state, all of which could have a material effect on current period earnings.

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Contingent Liabilities

A provision for legal, environmental and other contingencies is charged to expense when a loss is probable and the loss or range of loss can be reasonably estimated. Determining when liabilities and expenses should be recorded for these contingencies and the appropriate amounts of accruals is subject to an estimation process that requires subjective judgment of management. In certain cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies dealing with similar matters, and management’s decision on how it intends to respond to a particular matter; for example, a decision to contest it vigorously or a decision to seek a negotiated settlement. Actual losses can differ from estimates for various reasons, including differing interpretations of laws and opinions and assessments on the amount of damages. We closely monitor known and potential legal, environmental and other contingencies and make our best estimate of when or if to record liabilities and losses for matters based on available information.

Legislative and Regulatory Developments

The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels that result in stringent and costly requirements for our business. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a summary of significant laws and regulations that may affect us in the areas in which we operate. There is the potential for the revision or repeal of existing laws and regulations or the adoption of new legislation that could affect our industry.

Inflation

Inflationary pressures experienced in recent years may continue in 2025. Some of the underlying factors impacting inflation may include, but are not limited to, global supply chain disruptions, the imposition of trade restrictions or other governmental actions related to tariffs or trade policies, shipping bottlenecks, labor market constraints, increased competition for goods and services in response to improved energy industry operating conditions, and side effects from monetary and fiscal policies. If inflationary pressures persist or worsen, we may incur additional costs for equipment and materials, and from service providers. Our budgeted expenditures include an estimate for the impact of cost inflation and, despite inflationary pressures, we expect to continue generating significant amounts of free cash flow at current commodity price levels.

Table of Contents

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

General. We are exposed to a variety of market risks including commodity price risk, credit risk, and interest rate risk. We seek to address these risks through a program of risk management which may include the use of derivative instruments.

Commodity Price Risk. Our primary market risk exposure is in the prices we receive from sales of our crude oil, natural gas, and natural gas liquids. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas and natural gas liquids production. Commodity prices have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index prices. Based on our average daily production for the quarter ended December 31, 2024, and excluding any effect of our derivative instruments in place, our annual revenue would increase or decrease by approximately $846 million for each $10.00 per barrel change in crude oil prices at December 31, 2024 and $417 million for each $1.00 per Mcf change in natural gas prices at December 31, 2024.

To reduce price risk caused by market fluctuations in commodity prices, from time to time we economically hedge a portion of our anticipated production as part of our risk management program. In addition, we may utilize basis contracts to hedge the differential between derivative contract index prices and those of our physical pricing points. Reducing our exposure to price volatility helps secure funds to be used for our capital program and for general corporate purposes. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. We may choose not to hedge future production if the price environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to settle existing derivative positions prior to the expiration of their contractual maturities. While hedging, if utilized, may limit the downside risk of adverse price movements, it also may limit future revenues from upward price movements.

The fair value of our derivative instruments at December 31, 2024 was a net asset of $157.5 million, which is comprised of a $145 million net asset associated with our natural gas derivatives and a $12.5 million net asset associated with our crude oil derivatives. The following table shows how a hypothetical +/- 10% change in the underlying forward prices used to calculate the fair value of our derivatives would impact the fair value estimates as of December 31, 2024.


		Hypothetical Fair Value
In thousands	Change in Forward Price	Asset (Liability)
Crude Oil	-10%	$	22,574
Crude Oil	+10%	$	2,491
Natural Gas	-10%	$	376,230
Natural Gas	+10%	$	(86,275	)

Changes in the fair value of our derivatives from the above price sensitivities would produce a corresponding change in our total revenues.

Credit Risk. We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($1.2 billion in receivables at December 31, 2024) and our joint interest and other receivables ($382 million at December 31, 2024).

We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.

Joint interest receivables arise from billing the individuals and entities who own a partial interest in the wells we operate. These individuals and entities participate in our wells primarily based on their ownership in leases included in units on which we wish to drill. We can do very little to choose who participates in our wells. In order to minimize our exposure to this credit risk we generally request prepayment of drilling costs where it is allowed by contract or state law. For such prepayments, a liability is recorded and subsequently reduced as the associated work is performed. This liability was $65 million at December 31, 2024, which will be used to offset future capital costs when billed. In this manner, we reduce credit risk. We may have the right to place a lien on a co-owner’s interest in the well, to net production proceeds against amounts owed in order to secure payment or, if necessary, foreclose on the interest. Historically, our credit losses on joint interest receivables have been immaterial.

Interest Rate Risk. Our exposure to changes in interest rates relates to variable-rate borrowings we may have outstanding from time to time on our credit facility. Such borrowings bear interest at market-based interest rates plus a margin based on the terms of the

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(I.R.S. Employer Identification No.)

20 N. Broadway,

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CONTINENTAL RESOURCES, INC 10-K